1. Field of the Disclosure
This disclosure relates generally to oilfield wellbore drilling apparatus and more particularly to reverse drilling fluid circulation apparatus and systems and methods of using the same.
2. Background of the Art
Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drill pipe or drill string (tubing) that has at its bottom end a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) that carries the drill bit for drilling the wellbore. The drill pipe is made of jointed pipes. Alternatively, coiled tubing may be utilized to convey the drilling assembly. The drilling assembly usually includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as “mud”) is supplied or pumped under pressure from a source at the surface into the tubing. The drilling fluid drives the mud motor and then discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore and carries with it pieces of formation (commonly referred to as “cuttings”) cut or produced by the drill bit during drilling of the wellbore.
For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling), tubing is provided at a work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. For sub-sea drilling, a riser, formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the sea surface.
During drilling with conventional drilling fluid circulation systems, the drilling operator attempts to control the density of the drilling fluid supplied to the drill string at the surface so as to control pressure in the wellbore, including the bottomhole pressure. During such drilling, the surface pump supplies the drilling fluid into drill string that discharges at the drill bit bottom and moves upwards (toward the surface) through the annulus. Accordingly, the surface pump must overcome the frictional losses along both fluid paths (downward and upward). Moreover, the surface pump must maintain a flow rate in the annulus that provides sufficient fluid velocity to carry the rock bits disintegrated by the drill bit (referred to as “drill cuttings”) to the surface. Thus, in this conventional arrangement, the pumping capacity of the surface pump is typically selected to (i) overcome frictional losses present as the drilling fluid flows through the drill string and the annulus; and (ii) provide a flow velocity or flow rate that can carry or lift the cuttings through the annulus. Such pumps have relatively large pressure and flow rate capacities. Sometimes, the fluid pressure needed to provide the desired fluid flow rate through the annulus can fracture the earth formation surrounding the wellbore and thereby compromise the integrity of the wellbore at the fracture locations.
In another drilling arrangement, a surface pump is used for pumping the drilling fluid into the annulus between the drill string and the wellbore wall. The return fluid flows up the drill string tubular, carrying with it the drill cuttings. In such an arrangement, the surface pump has the burden of flowing the drilling fluid down the annulus and upwards along the drill string. Accordingly, the surface pump must overcome the frictional losses along both of these paths. However, due to the smaller cross-sectional area of the drill string compared to the annulus, the flow rate can be reduced assuming the same critical flow velocity for hole cleaning (transporting the cuttings to the surface). Thus, in such an arrangement, the pumping capacity of the surface pump is typically selected to (i) overcome frictional losses present through the annulus and the drill string; and (ii) provide a flow velocity or flow rate that can carry or lift the cuttings through the drill string. It will be appreciated that such pumps also have relatively low flow rate capacities.
The present disclosure provides drilling apparatus methods that address some of the above-noted and other drawbacks of conventional fluid circulation systems for drilling of wells.